Subterranean drilling of a bore hole or wellbore typically involves rotating a drill bit from surface or on a downhole motor at the remote end of a tubular drill string. It involves pumping a fluid down the inside of the tubular drillstring, through the drill bit, and circulating this fluid continuously back to surface via the drilled space between the hole/tubular, referred to as the annulus. This pumping mechanism is provided by positive displacement pumps that are connected to a manifold which connects to the drillstring, and the rate of flow into the drillstring depends on the speed of these pumps. The drillstring is comprised of sections of tubular joints connected end to end, and their respective outside diameter depends on the geometry of the hole being drilled and their effect on fluid hydraulics in the annulus.
The entire drillstring and bit are rotated using a rotary table, or using an above ground motor mounted on the top of the drill pipe known as a top drive. The bit can also be turned independently of the drillstring by a drilling fluid powered downhole motor, integrated into the drillstring just above the bit. Therefore speed of operation of the bit can vary with either the speed of the surface rotary mechanism or by the rate of pumping of drilling fluid through the downhole motor.
The bit is the apparatus which provides the necessary crushing/cutting action to penetrate the rock layers as the wellbore is drilled deeper, and it is used in combination with the weight provided by the entire drillstring that exists above it to provide the necessary force to penetrate the rock layers. Bit types vary and have different designs in their profile in regards to items such as cutter design and profile and are predominantly selected based on the formation type being drilled.
The bit penetrates its way through layers of underground formations until it reaches target prospects—rocks which contain hydrocarbons at a given temperature and pressure. These hydrocarbons are contained within the pore space of the rock (i.e. the void space) and can contain water, oil, and gas constituents—referred to as reservoirs. Due to overburden forces from layers of rock above, these reservoir fluids are contained and trapped within the pore space at a known or unknown pressure, referred to as pore pressure.
A fluid of a given density fills and circulates the annulus of the drilled hole. The purpose of this drilling fluid/mud is to lubricate, carry drilled rock cuttings to surface, cool the drill bit, and power the downhole motor and other tools. Mud is a very broad term and in this context it is used to describe any fluid or fluid mixture that covers a broad spectrum from air, nitrogen, misted fluids in air or nitrogen, foamed fluids with air or nitrogen, aerated or nitrified fluids, to heavily weighted mixtures of oil and water with solids particles. Most importantly this fluid and its resulting hydrostatic pressure—the pressure that it exerts at the bottom of the hole from its given density—prevent the reservoir fluids at their existing pore pressure from entering the drilled annulus. The drilling fluid must also exert a pressure less than the fracture pressure of the formation, which is where fluid will be forced into the rock as a result of pressure in the wellbore exceeding the formation's horizontal stress forces.
The bottom hole pressure (BHP) exerted by the hydrostatic pressure of the drilling fluid is the primary barrier for preventing influx from the formation. BHP can be expressed in terms of static BHP or dynamic/circulating BHP. Static BHP relates to the BHP value when the mud pumps are not in operation. Dynamic or circulating BHP refers to the BHP value when the pumps are in operation during drilling or circulating. It is the density property of the drilling fluid system that is primarily used for controlling the BHP so an influx event does not occur. Conventional methods use the density of the drilling fluid to control a point pressure in the wellbore, for example at the bottom of the hole (BHP), and are not used for pressure control along the entire length of the wellbore.
If the formation enters the well bore, this is referred to as a kick or influx. If the drilling fluid enters the rock, this is referred to as lost circulation or losses. Therefore the goal of a conventional drilling system is to maintain the BHP above the pore pressure but below the fracture pressure. The management of BHP to stay above the pore pressure and below the fracture pressure can be referred to as managed pressure drilling (MPD) or equivalent circulating density (ECD) management.
Equivalent circulating density (ECD) is the increase in bottom hole pressure (BHP) expressed as an increase in pressure that occurs only when drilling fluid is being circulated. This pressure is different to the hydrostatic pressure as the ECD calculation and value reflect the total friction losses in the annulus from the point of fluid exiting the bit at the wellbore bottom to surface as it flows up the annulus. The ECD can result in a bottom hole pressure that varies from being slightly to significantly higher than the bottom hole pressure when the drilling fluid is not being pumped through the system. The ECD is related to the circulating or drilling BHP in the sense that the ECD is calculated from the BHP. The ECD is directly related to the friction losses that are occurring along the entire length of the wellbore.
At the bottom of the tubular drillstring, downhole measuring devices are integrated into the drillstring above the downhole motor and bit. This allows the drilled hole to be steered in the appropriate direction to reach the reservoir target. Two important parameters measured downhole with these tools are the BHP and the bottom hole temperature (BHT) during drilling, circulating, static periods, and when pipe is removed or run into the wellbore. The measurement of BHP can be used to calculate the corresponding ECD. The measurement of BHT facilitates the temperature profiling over the entire wellbore length.
Therefore, the drilling fluid is pumped through the inside of the drillstring via a hose connected to the top of the drillstring, the hose injecting drilling fluid into the main internal bore of the drillstring. The fluid circulates down the entire internal length of the drillstring, through the bit, and returns to surface via the annulus. It carries with it drilled formation solids and keeps the drilled hole clean, thus substantially preventing a stuck bit or stuck pipe scenario as more solids enter the annulus from drilling.
Friction losses create pressure losses along the fluid's flow path in the annulus, so significant pressure is required to move the mud along its flow path. The friction losses occur between the fluid and the contact surfaces of the well bore and drill pipe. Some of the factors affecting friction losses are the geometry of the drillstring relative to the wellbore and the resultant annular clearance, fluid properties such as viscosity, fluid flow rate, and drillstring rotation RPM. It takes one or more positive displacement pumps to push the mud through the system at a suitable rate to ensure that the mud will effectively move solids, clean the hole, and power the bit while drilling. As the mud flows up the annulus, the greatest pressure is generated at the bottom of the hole from the summation of all the frictional losses occurring along the entire wellbore length.
The ECD and BHP are affected by the density of the drilling fluid, which is a variable that is controlled by use of additives in the drilling fluid. Such additives are well known in the art. A virgin or base fluid for a drilling fluid system with no additives has a specific density—by increasing the solids content in this fluid its density is increased. By diluting or decreasing the solids content in a drilling fluid its density is decreased. Both of these conditions are altered through mixing processes which occur at surface in the drilling fluid mud tanks and storage system. The density of a fluid is directly proportional to the hydrostatic pressure it exerts—a higher density fluid creates a higher hydrostatic pressure and vice versa.
Additional pressure effects can be imposed on the BHP with a closed loop system, such as the case with managed pressure drilling or underbalanced drilling. In these systems, flow is diverted by a device that seals around the tubular drillstring at surface, referred to as a rotating head, which diverts the return fluid flow via a pipe conduit, referred to as a flow line. The seal isolates the wellbore below from the atmosphere and provides pressure integrity to the system. The flow then passes through a choking mechanism known as a choke or control valve. By opening or closing the choke or control valve, back pressure is imposed on the total system the flowing return stream and annular volume, which increases or decreases the BHP.
Conventional practices for drilling fluid system design use careful selection of the density of the fluid and/or applied surface pressure through a choke valve as the primary control(s) for BHP during drilling, circulation and connections. The density and/or choke components are point pressure controls, however, and do not control the pressure/ECD along the entire wellbore length.